1. Field of the Invention
This invention relates to well drilling and treating, and more particularly to a method and composition for temporarily reducing the permeability of high-temperature, permeable oil-bearing formations.
2. Description of the Prior Art
In various well treating operations such as, for example, in the completion of wells in permeable hydrocarbon producing zones, and in stimulating the recovery of oil and gas from these producing zones, it is often advantageous to inject a fluid into the well in such a manner that the fluid is in contact with the earth formation penetrated by the well. However, in many instances, drilling muds, completion fluids, fracturing fluids, acid and other well treating liquids injected into the well bore preferentially flow into zones of high permeability, called thief zones. Not only does this result in loss and waste of the fluid, but also prevents the injected fluid from entering into zones of lower permeability in substantial quantities, thus causing poor distribution between zones of different permeability. Accordingly, low fluid loss agents, and in particular plugging agents, have been developed for use in these applications. In the above-mentioned applications it is essential that the temporary fluid loss control or plugging agent be readily removed from the hydrocarbon producing zones to prevent permanent loss of permeability and an attendant reduction in oil production rate. Removal of the plugging agent may be effectively accomplished by utilizing an agent that is soluble in the formation hydrocarbons. However, many of the prior art materials are either insoluble under bottom hole conditions, or are so highly soluble they are difficult to place in the formation and fail to maintain the required plug during the treating operation. It is therefore essential that the fluid loss or plugging agent possess a property of controlled solubility wherein a satisfactory solid plug will be formed for a period of time and whereupon the plug will thereafter be removed by being slowly dissolved by the formation hydrocarbons.
It is also advantageous to utilize a material that is insoluble in water, thereby leaving any water producing strata permanently sealed. Thus, selective plugging is effected, the hydrocarbon-producing strata is temporarily plugged and the water-producing strata remaining permanently sealed. On removal of the temporary plugging agent from the hydrocarbon-producing strata, oil and gas production capability is fully restored, while water production is permanently eliminated or substantially decreased.
Each of the aforesaid well treating processes commonly requires a temporary plugging material capable of being formed into small solid particles of controlled size, preferably by an inexpensive technique. The material should be slowly soluble in the formation hydrocarbons and insoluble in water at formation conditions to accomplish the desired selective plugging and complete restoration of hydrocarbon permeability. Particle size is important in controlling the distance that the plugging agent penetrates into the formation and the degree of fluid shutoff obtained. Therefore, it is essential that a large number of particles do not agglomerate or stick together in the treating fluid to form clumps of widely varying dimensions during the treating operation. While other properties of the particulate agent may influence particle agglomeration, agglomeration is largely controlled by the tackiness of the particle surface. Hence, it is necessary that the plugging agent particles exhibit a low degree of tackiness on exposure to air at ambient temperatures, and also remain non-tacky or non-sticky upon exposure to formation hydrocarbons and to treating fluids. In addition, particles which are somewhat resilient possess superior plugging properties since they deform to effectively fill flow passages. Also, high mechanical and impact strain is desirable to avoid size reduction of individual particles by attrition. Various slowly oil-soluble, water-insoluble particulate agents useful in well drilling and treating operations have been developed. In particular, U.S. Pat. No. 3,316,965 discloses the use of homogeneous solid particles of non-gaseous hydrocarbons and polymers; U.S. Pat. No. 3,342,263 discloses the use of discrete solid particles of homogeneous solid mixtures of polymers and halogenated aromatic hydrocarbons melting above about 125.degree. F.; U.S. Pat. No. 3,363,690 discloses the use of particles of homogeneous solid mixtures of a polymer and an alcohol melting above about 100.degree. F.; U.S. Pat. No. 3,302,719 discloses solid particles comprised of a homogeneous mixture of polymer, wax and resin. While these compositions are satisfactory in many well-drilling and treating applications and their use has contributed greatly to increased oil-recovery, they have not been completely successful in the treatment of high-temperature subterranean formations. U.S. Pat. No. 3,717,204 discloses the use of solid particles of a homogeneous solid mixture of polymer, wax and a solubility retarding agent where formation temperatures are between 200.degree. and 250.degree. F. Suitable solubility retarding agents disclosed are selected from long-chain aliphatic hydrocarbons, aliphatic amides and oxidized hydrocarbon waxes melting at a temperature between about 250.degree. and 325.degree. F.
The bottom-hole temperature of a well varies with the geographical location of the well and with its depth. For example, many producing wells have bottom-hole temperatures between 125.degree. and 155.degree. F. Other may have bottom-hole temperatures of above 200.degree. F., and often as high as 250.degree. F. and above. The current demand for increased oil reserves has resulted in more deep well exploration and production activity. As wells get deeper, high bottom-hole temperatures in excess of 300.degree. F. and often as high as 350.degree. F. and above are encountered. In order that the treated wells can be returned to full production, the injected and temporary plugging or diverting agents must be soluble in the reservoir oil at that reservoir temperature to the extent that substantially all of the plugging agent is removed within a reasonably short time, such as between about 1 and 6 days after returning the well to production. Solid compositions that are completely solubilized by the reservoir oil in less than 12 hours or greater than 6 days have been found to be undesirable for many of the well-treating processes. Many of the compositions disclosed in the foregoing patents are satisfactory for the treatment of formations having temperatures below about 180.degree. F., but are too soluble at higher temperatures to provide optimum treatment of a higher temperature formation. Even the compositions disclosed in U.S. Pat. No. 3,717,207 for treatment of formations having temperatures between 200.degree. and 250.degree. F. fail to provide an adequate plug for a sufficient period of time and do not possess the requisite properties of strength and non-tackiness in higher temperature formations. Thus, there exists a need for a particulate solid composition that has the characteristics of controlled slow oil solubility at high formation temperatures, and particularly at temperatures between about 350.degree. F. and above, that is insoluble in water, and that exhibits other requisite properties of hardness, strength and non-tackiness.